Drilling dysfunction causes premature failure of bits and motors in hard formations. Dysfunctions may be influenced by; bit design, bottom hole assembly (BHA) design, rig control systems, connection practices, and rotating head use. Sensors that record weight, torque, and vibration in the bit can offer insights that are not detectable further up the BHA. By understanding the root causes before the next bit run, it is possible to rapidly improve performance and prolong bit life. The formation being drilled in this study is a hard extremely abrasive shale, requiring 35+ runs per lateral section. The primary cause of polycrystalline diamond cutter (PDC) failure was smooth wear and thermal damage. The wear flats are attributed to abrasion and mechanical chipping that rapidly progress to thermal damage. Higher weights were not effective and it was hypothesized that buckling was occurring, causing insufficient weight transfer and increased lateral vibration. In-bit sensors that measure weight, torque, revolutions per minute (RPM), and lateral, axial and torsional vibration were run in hole to evaluate the weight transfer issues and dysfunction. High frequency downhole and surface data were combined with forensic images of the bit and BHA to confirm the weight transfer issues. In total, three major problems were identified and rectified during this study: drill string buckling, rate of penetration (ROP) loss due to the use of rotating control devices (RCDs) and WOB and differential pressure (DIFP) tare inconsistencies. Drill string buckling resulted in the downhole WOB being much less than surface WOB (DWOB<<SWOB) in early runs. Heavy weight drill pipe (HWDP) was run across the buckling zone to correct this. Subsequent runs showed a significant improvement in DWOB, reduction in lateral bit vibration, and improved performance and dull condition. Significant decreases in DWOB, DIFP, and ROP were noted when running tool joints through the RCD. Although observed before, in-bit accelerometers showed an increased lateral vibration that was a result of the loss in ROP and this continued long after the ROP recovered. DWOB and downhole torque (DTOR) were often much higher than SWOB and DIFP (converted to torque). Plots of hookload and stand pipe pressure tare values were used as indicators of inconsistent tares. Although premature motor failure were not noted in these runs, premature PDC cutter failure were. High frequency in-bit load sensing was used to identify persistent lateral vibration after a ROP loss event due to tool joints interacting with RCDs. A team based, continuous improvement, process was used to evaluate the root cause of downhole dysfunction and recommend bit/BHA design and operating procedure changes before the next bit was on bottom. This rapid analysis and joint recommendation process significantly prolonged bit life and improved drilling performance.

The objective of the auto driller is to maintain stable control of drilling parameters to reduce the time per stand and increase single run sections when possible. Large variation in rate of penetration, weight on bit, differential pressure, torque, and rotary speed have been found to damage the bit, motor, and bottomhole assembly (BHA), reducing the performance and life of these tools. During operations it was found that some instability in drilling parameters was introduced by the auto driller. The first attempt was to find the best set point combination to improve stability and net rate of penetration (ROP). This helped, but the system still tended to be unstable with changes in formation. The next step was to adjust the auto driller tuning parameters to improve system stability. The tuning was modified so that the system could be stabilized over the range of formations being drilled and were sent to the real-time centers and recorded to become part of the drilling roadmap. The net rate of penetration, or minutes per stand, was used as a key metric for real time performance. Variation in rate of penetration, weight on bit, differential pressure, torque, and rotary speed were used as leading indicators of BHA stress and thus life expectancy. Manually tuning these systems on the rig, with intensive support from the operator’s and contractors subject matter experts, and real time centers resulted in a reduction in drilling time and stress on downhole motors and tools. The drilling time was improved from 30-50 minutes per stand to 18-25 minutes per stand in the fast drilling part of the lateral interval (about 1500 meters). Furthermore, the fluctuation of the drilling parameters were reduced to two-thirds compared to previous wells. The drilling team completed its first shoe-to-TD single run in two years in the 8-1/2" section, typically requiring three BHAs. This was drilled in about half the time compared to the prior single run and was followed by another 3000-meter single run lateral. The downhole temperature in this section exceeded the motor vendor’s specifications and reducing the stress on the BHA due to parameter variation was critical in improving performance. Key performance indicators were developed to measure the health and function of the auto driller system. These were shown to be useful as real time and leading indicators of performance. A case study demonstrates how to use these KPIs to manually tune the system while drilling. Finally an example is shown on how to use source code from the Open Source Drilling Community to help tune the system offline and make it more robust to formation changes.